The measurement of fluid flow in particular during the production of an oil and gas well is important for proper monitoring and control of fluid from the reservoir.
The fluid in hydrocarbon boreholes generally flows through a conduit and the fluid normally comprises water, gas and oil in continuous and discontinuous phases. The gas and liquid are typically known to flow as bubble, churn, slug or annular flow generally depending on the gas flow rate relative to the liquid flow rate. The prior art discloses water cut meters which are devices for determining the water holdup in a producing well by measuring the capacitance or impedance of the fluid. The term is actually a misnomer because water cut is not the same as water holdup except in the unlikely case where all phases flow at the same velocity. Since hydrocarbons travel faster than water in a production well, the water holdup is larger than the water cut. However, a water cut meter has often been combined with a flowmeter so that the water cut could be estimated by combining the two measurements. The proportion of the total flow rate due to a fluid component is known as its cut. To determine in-situ flow rates, it is necessary to measure the holdup and velocity of each fluid component.
Total water in fluid flow from hydrocarbon boreholes generally comprises free water plus suspended water in an emulsion and dissolved water. Free water is completely separated from any emulsion and not dissolved. The amount of dissolved water is generally very low, e.g. in the range of 0.01%–0.1%, and is generally influenced by interfacial properties but only minimally effected by temperature and pressure. The water volume flow rate, relative to the total liquid (e.g. oil and water) flow rate, is known as water cut when standardized with respect to pressure and temperature. Water cut is generally expressed as a percentage.
Oil and water from oil wells typically flow in an emulsion which may be in two different forms. In one emulsion form, the oil is the continuous phase having water dispersed in the oil as droplets. The foregoing emulsion has insulating electrical properties wherein the dielectric constant of the oil continuous emulsion may be measured by a capacitance sensor. Another emulsion form comprises a water continuous phase having oil dispersed in the water as droplets. This emulsion form has electrically conductive properties wherein the conductivity of the water continuous emulsion may be measured by a conductive sensor. Therefore, the electrical properties of these two different types of emulsion forms are completely different even for instances when the water cut may be the same. The prior art typically measures electrical properties and densities of the phase and emulsion flows by methods known to those skilled in the art in order to determine corresponding flow rates, e.g. by using look-up tables.
The prior art also discloses methods and apparatus to determine component flow rates in a water continuous phase emulsion by using, for example, fluid conductivity measurements. Typically, the prior art discloses methods and apparatuses for measuring component flow rates in a fluid comprising oil continuous or water continuous emulsions which may switch from using capacitance sensors to conductive sensors at the instant a water continuous phase emulsion is detected by the flow meter apparatus.
In a vertical upward gas-liquid flow in a borehole conduit, the larger gas bubbles or slugs will rise in the fast moving liquid in the center of the conduit; other small bubbles will be near the wall of the conduit and will consequently move more slowly. This velocity slip is further enhanced by buoyancy due to the difference in density of gas and liquid so that the gas phase will be transported with a larger average velocity than the liquid phase. In order to measure multiphase flow rates, the prior art discloses the total velocity distribution of the flow must be measured in order to derive the flow rates from these measurements. If a flow meter apparatus does not take into account velocity slip, the volumetric measurements may be expected to be encumbered with a large degree of uncertainty.
Within a certain range of multiphase compositions and flow rates, the prior art discloses that an inline mixer may be employed in order to reduce the velocity slip to a minimum in an effort to create a radially homogeneous phase distribution at the location of a positioned multiphase flow meter apparatus in the borehole conduit. However, using an inline mixer has the following major drawbacks: the prior art does not disclose that a multiphase inline mixer exists that can create a homogeneous phase distribution over a sufficiently large range of flow rates for all the compositions that may be found in the field and thus, the range of a multiphase flow meter apparatus employing an inline mixer will be limited; pressure drops which may occur from using an inline mixer may be significant and detrimental to economic and process efficiency; an inline mixer may result in lost production by promoting emulsion formation; and use of an inline mixer increases measurement uncertainty.
The prior art also discloses derivation of empirical models whereby phase slip is related to measurable fluid parameters such as phase fractions and measured velocity adjusted to account for fluid temperature and pressure. However, the foregoing methodology has a disadvantage because a universal model covering all possible component composition scenarios and conditions encountered in the field is not possible. Furthermore, since flow regime is dependent on fluid property parameters such as pressure, viscosity and upstream configuration, a high uncertainty in slip determination occurs.
The prior art discloses a dual velocity method in order to avoid the use of inline mixing or empirical modeling to determine velocity slip. The dual velocity method directly measures velocity slip by measuring the two most predominant velocities in a multiphase velocity distribution, by measuring the velocity of a pseudo-homogenous dispersed phase and by measuring the average velocity of the gas flowing as large slugs.